Ladies and gentlemen, good morning, and welcome to the Dominion Energy Second Quarter Earnings Conference Call. [Operator Instructions]. It's now my pleasure to turn the conference over to Mr. Steven Ridge, Vice President, Investor Relations.

Good morning, and welcome to the second quarter 2019 earnings conference call for Dominion Energy. I encourage you to visit our Investor Relations website to view the earnings press release, a slide presentation that will follow this morning's prepared remarks and additional quarterly disclosures. Schedules in the Earnings Release Kit are intended to answer detailed questions pertaining to operating statistics and accounting, and the Investor Relations team will be available immediately after the call to answer additional questions. The earnings release and other matters that will be discussed on the call today may contain forward-looking statements and estimates that are subject to various risks and uncertainties. Please refer to our SEC filings, including our most recent annual reports on Form 10-K and our quarterly reports on Form 10-Q for a discussion of factors that may cause results to differ from management's projections, forecasts, estimates and expectations. Also on this call, we will discuss some measures of our company's performance that differ from those recognized by GAAP. Reconciliation of our non-GAAP measures to the most directly comparable GAAP financial measures, which we are able to calculate and report are contained in the Earnings Release Kit. Joining today's call are Tom Farrell, Chairman, President and Chief Executive Officer; Jim Chapman, Executive Vice President, Chief Financial Officer and Treasurer; and other members of the Executive management team. I will now turn the call over to Jim.

Good morning. Dominion Energy reported second quarter 2019 operating earnings of $0.77 per share compared to our guidance range of $0.70 to $0.80 per share. Performance across our businesses was aided by better-than-normal weather, which increased utility earnings by about $0.02 per share. Adjusted for normal weather, operating earnings for the fourth quarter were $0.75 per share, which is also the midpoint of our guidance range. Operating segment performance for the second quarter is shown on Slide 4. GAAP earnings for the quarter are $0.05 per share, which were driven primarily by charges related to the SCANA integration and the voluntary retirement program, which I will discuss in a moment. A reconciliation of operating earnings to reported earnings can be found on Schedule 2 of the Earnings Release Kit. I will now provide updates on several ongoing initiatives. Turning to Slide 5. As announced at our Investor Day in March, we continue to work towards completing the restructuring of our reporting segments. During our fourth quarter earnings call early next year, we expect to provide our 2019 full year results as well as our 2020 guidance in conformity with these updated segments. As discussed previously, we believe that this new reporting structure will make our company more transparent to all stakeholders and will highlight the premium nature of each of our distinct businesses. Similar to last quarter, the Alternate Breakdown Structure or ABS will be posted to our Investor Relations website shortly after this call. This document provides a preliminary view of our future intended reporting segment results. The ABS, which is not reflective of how we currently manage our businesses, is not intended to replace Dominion Energy's current operating segment disclosures. Turning to Slide 6. We have concluded the previously announced voluntary retirement program or VRP. Though some retirements will become effective only in the coming months, most of our colleagues who elected to participate have already begun to enjoy their retirement. Roughly 12% of our total workforce elected to participate, which compares to an average annual retirement rate over the last 5 years of just over 3%. We, of course, wish them all the best in retirement and also thank them for their many years of dedicated service. We expect this VRP to be impactful to our company and our workforce in a number of ways, in particular as we embark on industry-leading innovation initiatives highlighted by Tom and other members of our senior management team at our Investor Day in March. As it relates to thinking about the potential financial impact of the program, I would ask that you note the following: first, while the VRP's financial impacts are incremental to our previously announced Flat O&M initiative, I reiterate my comments from the first quarter call that these savings should not be considered passive to existing earnings guidance. Rather the savings from the VRP are available to overcome potential unexpected challenges and derisk the execution of our earnings growth plan. We view this approach as supportive of our objective to consistently and predictively deliver results in line with our guidance, which we expect would be a driver of premium equity valuation. Second, the bottom line impact of this program will be influenced by near-term backfilling of up to 1/3 of the vacated positions given operational and safety requirement. Further, O&M savings in our regulated businesses accrue to our customers immediately, in the case of rider programs and over longer time frames via rate proceedings. Finally, VRP savings in our Southeast Energy Group are supportive of the expected transaction accretion of approximately $0.10 per share in each of the first two years following merger closing. Turning to financing. In June, we successfully placed approximately $1.6 billion in equity-linked units, consistent with our financing plan guidance. Due to a high-quality order book that was many times oversubscribed, we were able to achieve record pricing in terms of spread to common yield for security of this type. As a reminder, this transaction does not result in any near-term common stock issuance, and the financial impacts of this issuance were already contemplated in our existing earnings guidance. As discussed during our Investor Day, over the next several years, on average, we continue to expect nonmarketed equity issuance via DRIP of about $300 million per year and via our aftermarket program of some $300 million to $500 million per year to help prudently fund our sizable regulated capital investment program. Moving now to operating earnings guidance on Slide 7. As usual, our operating earnings guidance ranges assume normal weather, variations from which could cause results to be towards the top or the bottom of these ranges. For the third quarter, we are initiating guidance of $1 to $1.20 per share. Positive factors as compared to last year include growth from regulated investment across electric and gas utility programs, the contribution from the Southeast Energy Group and the impact of O&M initiatives. Negative factors as compared to last year include the impact of 2018 asset sales, share issuances, timing of a farm-out and return to normal weather. As you evaluate the cadence of our quarterly earnings as compared to last year, particularly as it relates to the second half of the year, please keep in mind the following factors, some of which have been quantified on the right-hand side of Slide 7: the timing of the Millstone refueling outage, which occurred in spring this year as compared to the fall last year; the favorable net impact of PJM capacity prices, including our new Greensville power station's participation in the capacity market for the first time since it's in service late last year; the contribution of the Southeast Energy Group; earnings growth from continued regulated investment across electric and gas businesses; higher realized prices at our Millstone Power Station driven primarily by an expected October 1 effective date for the 10-year, 9 million megawatt-hour, zero-carbon contract with Connecticut utilities; and finally, the continuation of our Flat O&M and other expense control initiatives. We expect that savings from the VRP, net of the mitigants just discussed will be between $0.05 and $0.06 per share during the second half of this year. These savings are available to address unplanned challenges that may arise, for example, items like the $0.04 of negative weather experienced so far this year. We are also affirming our expectations for full year 2019 operating earnings per share between $4.05 and $4.40. Similarly, we also reiterate our long-term EPS growth expectation of approximately 5% per year through next year and 5%-plus thereafter. I will now turn the call over to Tom.

Thank you, Jim, and good morning. First, a reminder that safety is our first core value. It is at the heart of our corporate culture, and we will continue to improve until we achieve the only acceptable safety statistic, 0 injuries. Though 6 months remain, year-to-date safety results are consistent with the record-setting results we have achieved in the last few years. Of particular note, the Southeast Energy Group overall safety performance has improved from what was already solid results, overcoming a loss of a colleague in the tragic event in Durham on April 10 from a third-party contractor and avoiding distractions from merger activities. I want to commend the women and men of the Southeast Energy Group who have responded so positively, providing safe, reliable and efficient delivery of energy to customers who are experiencing lower bills and seeing increased community giving, just as we committed prior to completion of the merger. Turning to Slide 9. Earlier this month, CNBC released their 2019 update to America's Top States for Business. We were pleased, though not surprised, to see 4 of our 5 primary state-regulated jurisdictions ranked in the top 10 of the list, including Virginia, which was recognized as the nation's #1 state for business. You might recall from our Investor Day that 65% to 70% of our company's expected 2020 operating earnings are from state-regulated operations centered around these 5 key states, including 40% to 45% attributable to our Virginia-phased utility. This is just one more validation of the theme we have highlighted regarding the differentiated nature of our high-quality regulated operations. Another topic we regularly highlight to all Dominion Energy stakeholders is our ongoing ESG efforts. We're continuously enhancing our strategy in this area and increasing our communications regarding the progress we have made and will continue to make. For example, to our knowledge, we were the first utility company, and we believe the only U.S. company in any sector, to hold a dedicated ESG-focused Investor Day meeting. We created a new Board-level Sustainability and Corporate Responsibility Committee that oversees our approach to these matters. We have updated our emissions reduction goals to be more aggressive. We have improved our disclosures across-the-board, including inclusion of comparable ESG metrics. They are included in the appendix of these earnings call materials. We have directly engaged with our largest institutional investors outside of proxy season in discussions about Dominion's industry-leading positions on these issues. And we are only 1 of 3 utility companies that have implemented an environmental justice policy, which ensures that all stakeholders including local communities have a voice in decisions on infrastructure investments. We believe that as investors become increasingly discerning around ESG criteria, Dominion's industry-leading efforts will be rewarded with a differentiated positive investment outlook. I will turn now to recent updates related to our major investment initiatives. Earlier this month, we began construction of our $300 million offshore wind pilot project. The project was approved by Virginia regulators in November of last year and is a critical initial step in what has the potential to become a multiyear, multibillion dollar capital deployment in zero-carbon offshore wind energy. Recall that our Virginia offshore lease should accommodate over 2 gigawatts of generation capacity based on expected technology advancements, which is significantly more than what we have accounted for over our 5-year planning horizon. We continue to make progress on the $2 billion to $3 billion new pump storage facility. It would be an excellent complement to the intermittency of the increased wind and solar resources across our system. During the second quarter, we narrowed the search for a potential location, and we'll spend the remainder of this year and part of next conducting more extensive surveys. The Virginia General Assembly has found the construction of such a facility to be in the public interest. Next, relicensing of our existing regulated nuclear units in Virginia is an up to $4 billion capital program that supports safe, reliable and affordable energy for customers and is an important source of zero-carbon electricity production. During the second quarter, our nuclear station in Surry County generated its 500 billionth kilowatt-hour of zero-carbon electricity. Put that into context, 500 billion kilowatt-hours would power the entire state of Virginia for 5.5 years in a carbon-free manner. Later this week, we will file our first battery pilot program. We will pair batteries with solar facilities to begin the integration of peak shifting and clipping as well as test of reliability benefits of batteries on our distribution grid. On Slide 12, we have charted positive trends across 2 significant growth drivers for our power delivery business. On the left side, you can see the growth in electric transmission rate base, which will continue as we execute on the 5-year, $4.3 billion capital plan we shared at our Investor Day in March. These transmission investments improve system reliability to the benefit of our customers. On the right side, you see the impressive growth in data center capacity, which we also expect to continue for years to come. Our capital planning calls for $1.7 billion of investment associated with customer growth, including data centers over the next 5 years. And finally, with regard to the Atlantic Coast Pipeline and Supply Header. Our customers continue to meet this project's capacity to serve their existing customers, move toward a low-carbon future and enable new economic development. It is noteworthy that natural gas prices in the region that will be served by the project remain among the highest in the country. We are pleased that the Solicitor General filed an appeal to the Supreme Court of the Fourth Circuit Cowpasture decision as it relates to ACP's crossing underneath the Appalachian Trail. To date, 16 states, the AGA, INGA, the Chamber of Commerce, several unions, the National Association of Manufacturers, Mountain Valley Pipeline have all filed amicus briefs. History indicates cases appealed by the Solicitor General have an approximately 70% chance of being considered. We expect that in October or November, the Supreme Court will schedule arguments to occur in the spring of next year with a final decision no later than June 2020. We are confident that the Fourth Circuit's ruling will be overturned. And though at present, we are not publicly discussing potential administrative or legislative alternatives, the options that have been described by the developers of the Mountain Valley Pipeline should be expected to be applicable to the Atlantic Coast Pipeline. We are disappointed that last week, the Fourth Circuit vacated the project's biological opinion. Over recent months, we have been taking steps to bolster the official record of the case in the event the court ruled negatively. These steps include the additional surveying of the rusty patched bumble bee along the Project corridor, which has been underway since mid-June. There's nothing in the court's opinion on the poor species that we expect would prevent the biological opinion from being reissued in time to recommence construction by year-end and complete critical path tree filling during the November through March window. We have included in the appendix a list of select outstanding regulatory reauthorizations, including resolution timing expectations. Based on the assumptions, our current project cost and in-service timing expectations remain consistent with the guidance we provided earlier this year on our fourth quarter earnings call. Before I complete my remarks, I would like to add my personal thanks and well wishes to our colleagues who have opted to retire on an accelerated timeline. Your legacy of living our core values will leave a lasting impression at Dominion Energy and you will be missed. With that, I will summarize today's release as follows: we are on track to achieve full year safety results that are consistent with the record-setting performances of recent years. We are actively engaged throughout the company on initiatives that are focused on creating shareholder, customer and other stakeholder value by making Dominion Energy more efficient, sustainable and transparent. We achieved operating earnings per share above, or on a weather-normalized basis, at the midpoint of our guidance range. We are affirming our full year operating earnings per share guidance and our long-term growth rates. Our key regulated jurisdictions stand apart as premium locations in which to do business. We are making progress across our capital investment programs to the benefit of our customers. And we have a strong environmental, social and governance track record and strategy, and we will continue to increase our engagement with customers, shareholders and other stakeholders on those topics. We will now be happy to answer your questions.

[Operator Instructions]. Our first question will come from Greg Gordon with Evercore ISI.

So two questions, one numbers related question. Looking at the adjustments from GAAP to operating. On an operating basis, you obviously had a really great quarter, congrats on that. But pretty significant charges associated with merger integrated -- merger and integration costs, the retirements, et cetera. Are those numbers consistent with your expectations for the year on the delta between GAAP and operating? And are there any significant incremental charges we should expect as adjustments for the balance of the year and going into 2020?

Yes, Greg. It's Jim, good morning, thanks. The future nonoperating charges are, of course, difficult to predict so we don' know exactly what those will be, it’s the nature of the beast. I would expect some continued charges related to our integration of SEG the former SCANA business mostly in terms of accounting systems and implementations and things along those lines. The major charges related to customer benefit, and VRP and related restructuring have been kind of tackled in the first half of this year. So some numbers would continue but they will be, we expect, more modest than what we've seen so far.

My second question goes to your confidence in your ability to get the Fish and Wildlife Service to effectively mediate the concerns associated with this second certification of their permits from the Fourth Circuit. In reading that document, I've had varying opinions -- heard varying opinions on how high the hurdle is that the Fish and Wildlife Service needs to get over in order to issue a valid permit given some of the pretty strong language in that. While it was a detailed brief -- they gave very good detail as to why they felt that the decision was arbitrary and capricious. Some people's opinion that the standard that they've put the Fish and Wildlife Service to and the details of what they have problems with might be very difficult to meet. So could you just comment on why you think, based on your reading and your experts reading, that you can meet those hurdles with just more information on the three other species and adequately doing the survey on the bees. Sorry for such a long-winded question.

Well, all right. Go ahead, Diane.

Okay. This is Diane Leopold. Really what I would say as we look at the 4 species is there was an enormous amount of information and analysis that went into the process to begin with while we were in formal consultation with the Fish and Wildlife Service. And based on the amount of information that they have and the surveys that we have completed, we believe based on -- there's nothing surprising that's coming out of it that would make us think that they cannot resolve it with the enormous amount of analysis and information that they have.

I will just add one thing. The surveys -- the one issue they had is they didn't think enough surveys were done around the bees, and we've been doing those surveys since mid-June. They'll be done this quarter and there will be more than sufficient facts, we believe, to just by issuing the BL.

Our next question comes from Steve Fleishman with Wolfe Research.

Could you guys maybe just give a little color on how you'd characterize your natural gas midstream system in light of some of the concerns on Appalachia gas? I know it's mainly regulated and with long-term contracts. But just obviously, you saw Blue Racer very timely. Just maybe give some color and context of that.

Diane Leopold again. What I would do is say that part of the reason that we divested Blue Racer is that really wasn't core to us. When we look at our gas infrastructure, our high focus in both our existing customers and our growth project has been in end-use markets, and end-use markets actually benefit from the low gas prices that you see. So while we understand the Appalachian gas prices are quite low, what that's done is it's driven a higher industrial growth in that region and more end use and PowerGen customers. So as Tom talked about in the Analyst Day back in March, a lot of our focus is towards the end use rather than the producers.

Okay, great. And then I guess, the other question would be just on the savings for the voluntary retirement and the benefits of that. So when you look at unexpected pressures, the only one that I could think of right now would be ACP-related. I guess since they're unexpected, there's not any other that you see right now that could be out there in terms of dealing with using these benefits or needing the benefits.

Well, that's right, Steve. I mean, unexpected is unexpected so hard to comment. I mean we think about -- let's put it in context. So we mentioned -- I mentioned, and we have on the slide there that the net impact, none of the mitigants I described, for this year in the $0.05 to $0.06 range for the second half of the year. So you could easily annualize that for a year in the coming years. Of course, over time, that's given back to our customers through to rates [indiscernible]. For 2020, fair enough, think about double that amount, so it’s $0.10 to $0.12. So let's just put that in context. So $0.04 of weather hurt this year 6 months, we don't know what that will be the rest of the year. Or, of course, in 2020 that kind of thing stands ready to offset. When it comes to ACP, as a reminder, our guidance on the contribution from ACP in 2018 last year was $0.07. This year, it's $0.11. Next year, we have a little more visibility but not on a granular basis yet regarding the exact timing of recommencement and the sculpting of capital spend through 2020. So what the contribution in 2020 is, we don't yet know exactly but call it mid-teens to high teens, at best, contribution. So the $0.10 to $0.12 stands available to offset various unforeseen challenges, but that kind of puts it in context versus ACP, which you're asking about, smaller.

Okay. And then one just clarification on that. The $0.10, $0.12, is that after any future kind of pass-through to customers through clauses and such? Is that -- that's just the net number that would not pass through?

Yes, that's right. I mean, over a number of years, that will go back to customers as mentioned. But for the near-term number, $0.05 to $0.06 is net of the amount that is immediately passed to customers through rider tax treatment. And that holds true for 2020 as well. After that, it tends to blend back to customers over time but for 2020, it is net of that factor.

Our next question comes from Shar Pourreza with Guggenheim Partners.

Real quick, Tom. You commented, Tom, a little bit on sort of briefly touched on the administrative path and potentially looking at like a land swap similar to what we've seen with MVP. Are there other sort of administrative solutions that you could be looking at outside of just the land swap?

Yes, there are a number. And as we said before, we really don't want to get into a lengthy discussion about what all those options are. There has been some discussions from the developers of the MVP pipeline that as I've said a few minutes ago, we would expect all of those solutions to be available to us as well.

And then just from a timing perspective of when you're ready to discuss publicly the administrative or legislative path, is that sort of at a point when SCOTUS affirms whether they would hear this case or not?

We're completely focused on that right now. This is -- the Fourth Circuit decision is a very poor precedent, we think, for energy policy in the United States, setting up a 2,000-mile-long barrier wall to bring energy resources from the Midwest and South, the western parts of the country into the East. Don't think that's what compressible intent was. So it's very important that the precedent not stand.

Got it, okay. And then just -- I don't know if you can comment on this but there's obviously been some headlines around the retail business and potentially looking at a transaction down there. Is there anything you can elaborate on that, how the process is going?

Yes. Sure. let me give some color on that point. And obviously, for the norm, we don't really comment on material M&A. But I'm using color on the way we think about this. So we're always considering ways to create shareholder value to derisk our plan, to take our exposure to regulated and regulated-like businesses which now 95%, take it up towards 100%. So last year in 2018, obviously we made a lot of progress in that respect, as you know. And this year, that continued but on a totally different scale. We're really focusing on that last 5%, for the most part, of things that are not core or not regulated or regulated-like. For example, we divested a 15-megawatt fuel cell asset we had in Connecticut in Bridgeport for $35 million this year. We also divested our stake in NedPower, the wind facility in West Virginia. The amount wasn't disclosed but is modest. We're also fielding and thinking about what to do with another wind asset we own in Indiana, which is Fowler Ridge, no decisions there yet, early days. So that kind of thing, we're always thinking about it but it's very modest. Now I say that to put in context for retail, which is your question. So there are press reports about potential sales of our retail gas and -- there also, we've been fielding inbound inquiries on all of it, on the part that is in Georgia that was formerly SCANA business, on the legacy Dominion business. And we're thinking through that. There's certainly no decision. But importantly, we're thinking about what to do generally, so it's not so focused on the process. Should we keep it as well? How can we grow it? Could there be ways to grow through JV, for example, or some other structure? So it's more thinking along the lines as opposed to, "Let's sell this thing," because we're probably not going to do that. It's not accretive. So no decisions, lots of thought processes. But no, nothing to share and not sure there will be.

Got it. And then as we think about like redeployment of proceeds in case there is a process, is that strictly into delevering and strengthening the balance sheet?

I would call it yes, but I would put that in the kind of the general corporate when we're talking about not huge numbers in the scope of all of Dominion.

Our next question will come from Michael Weinstein with Crédit Suisse.

Just a couple of follow-up questions. The $0.10 to $0.12 of voluntary savings, the voluntary retirement savings, you said that you expect to eventually see it in a few years as the savings are shared with customers. How much do you think you'll retain though longer term once most of those savings have been shared?

Yes, Michael, we don't really have such a number. I mean it'll -- over the years, we don't have material rate cases with all that much frequency. So it will be chipped away over time, but we don't have a specific number to bifurcate between what's kept it long term and what's not.

But just, I mean, roughly speaking, half, would you think, or below half or more than half maybe?

Half would be fair. We don't really have a number in mind.

Okay. And then on -- how much capital has been put into ACP to date at this point? And what is the assumption that is going into that mid-teens EPS number that I think that you mentioned earlier from AFUDC next year?

Yes. As of June 30, the total cash invested capital is $3.4 billion from all parties from all forms. Now half of that is funded, as you know, with the construction facilities at the project level, and you'll see that in our quarterly reports, that's $1.7 billion, so twice that. The other half is just the total and the other half comes pro rata from the equity contributions from the sponsors worth 48% of that. So $3.4 billion is the total. The -- as I mentioned, we don't have available, at this time, granular guidance on the capital spend for the end of this year or the sculpting of it through 2020, but it assumes recommencement of construction by the tree clearing season in the fourth quarter this year.

So when you say mid-teens on the next two years, that's sort of an assumption that you are going to get most of this built up into the Supreme Court decision?

It's mid- to high teens so mid would be with less under construction during 2020 or later in 2020, and higher would be again most of it.

Our next question comes from Julien Dumoulin-Smith with Bank of America. Julien Dumoulin-Smith: So perhaps just to follow up on some of the last questions here. Can you talk a little bit more about what else might be considered sort of not necessarily noncore but as you think about kind of fine-tuning the portfolio here within the regulated bees. And more specifically, I'd be curious, given some of the developments here around Millstone that have been achieved, is there any way to derisk some of the volatility ahead as well over time, for instance, within that example?

Well, I'll talk about Millstone. We have derisked Millstone with the legislative and regulatory solution that's in its final weeks right now with a very significant portion of the output being sold to the utilities for a 10-year period. So we'd consider that to be more than sufficient derisking of the Millstone asset. I'll let Jim and others answer the rest of the questions.

I think that's a good answer. And going back to the way I've started my answer to Shar, I mean, we don't comment on material M&A. But the review of real material things, which are noncore, including Blue Racer, as we talked about last year, and our last remaining fossil merchant plant last year, I mean, for big items, that pretty much exhaust the list. Julien Dumoulin-Smith: And then just coming back to the question around VRP, I know it's been asked a few different ways. But as you look in the back of this year, could you think about like the pluses and minuses here? Clearly, it's a big plus. Any offsets in terms of execution? That it sounds like that's already been largely recognized in the first half to achieve this? And maybe the punchline is how do you think about this trending for the full year '19, given the 3Q guidance you've already issued and what that means for 4Q as well.

Okay. Let me talk about that a little bit. I know it's a little bit funny to talk about that savings as being kind of available for unforeseen headwinds, whether it's the most prevalent. We always talk about the potentially material impact of weather now in Virginia and South Carolina on our earnings guidance ranges and where we end up. So it's hard to point any one thing because we feel pretty good about where we are at this stage, given what's to come in the next 2 quarters. And let me address that a little more. So last year, as we sat here on our second quarter call and we looked at kind of what was remaining, what we needed to do after our first two quarters to get to the midpoint of our guidance range, we needed $2.03. So this year, as I mentioned in my prepared remarks, the cadence is different. We have a back-end loaded profile to our EPS accrual through the second half of the year. So last year was $2.03. This year, it's $2.36, so bigger company, more earnings, but we also need have a little bit of catch-up, it's back-end loaded. The reasons for that and the reasons we are comfortable with that are these things that are generally set out in that right-hand side of Page 7 in our deck. So the Millstone outage, $0.08 to $0.10. Last year was in fourth quarter, and for the most part, this year, done in spring. The net capacity expansion, PJM with Greensville in the next now starting in June, $0.06 to $0.08. The VRP also in the mix, $0.05 to $0.06. Southeast Energy Group didn't have it last year, $0.04 to $0.06. And then another basket of things are smaller but regulated investment across our utility business for the next 6 months: the Millstone PPA we mentioned, assuming that comes into place October 1; and then the continued impact of O&M to the next 6 months. So in our minds, we don't really have one thing that the VRP will offset. It's just there and available. So we anticipate Julien that a question, which was what if nothing comes up this year or next year? And there also, we're saying, I've said that it's not additive to our guidance. So if nothing comes up and we're in the lucky position of not having any headwinds that aren't expected or such event, what I would do is identify areas in O&M to advance spending in order to use that VRP savings to derisk our guidance, our earnings guidance for a longer period of time. So not a very direct answer to your question but that's the way we think about the VRP savings and what it will potentially help us with over the next period. Julien Dumoulin-Smith: Right. So maybe said differently, 2019, there's a lots of puts and takes. You feel very comfortable still. I don't want to put words directly in your mouth for '19. And then you've been a story for '20, again, this is going to be more about accelerating forward O&M that you might otherwise need, for instance, in '21 or something.

Yes, if no other headwinds pop up, that's right.

Our next question comes from Stephen Byrd with Morgan Stanley.

Just had one follow-up on Atlantic Coast Pipeline. Assuming that a revised biological opinion and incidental take statement is issued but is stayed by the court yet again, what would the next process steps be at that point? Is there an appeal process or where would you go at that point if the unrevised is yet again stayed?

Well, you can do a preliminary -- you can appeal a stay. You can -- need to tell, it will depend on what the stay was for if one was entered at all. Would it be the entire 600 miles or would it be a segment? Also it's kind of difficult to answer that question. There are a variety of remedies we can pursue but without a real detailed issue, it's hard to answer that question.

Our next question comes from Praful Mehta with Citigroup.

Moving a little bit away from ACP, wanted to touch on offshore wind. I know you talked about it and emphasized on the call the opportunity on offshore wind. Firstly, wanted to understand the economics that you're seeing and the benefits you're seeing on the technology side. And given the investment that you've talked about as a potential opportunity, is that going to put pressure on bills and would that constrain the opportunities? So just a little bit color on that will be helpful.

This is Paul Koonce. Of course, we're under construction on the two offshore wind turbines now, doing the onshore construction next summer will complete the two test turbines. In terms of the offshore wind economics, we've been watching very closely what's been happening throughout New England. I would say that the life cycle cost equivalent, LCOE, in those markets have been, call it, $85 and potentially higher. There's some speculation what may happen with production tax credits for offshore wind. Might they be renewed or not? We don't know. In Virginia, we're looking at the need to get the life cycle cost equivalent down closer to maybe the $80 range, which means we need to see about a 15% to 20% capital cost improvement. We think that those costs can move in that direction once we stand up the U.S. supply chain. That's been a real benefit that they've seen in Europe is being able to scale up the supply chain. And we also think that the development of larger turbines, 11 megawatt and greater, will drop those costs down closer to what we think we need in order to really see the build-out in Virginia. So we're watching all of that very closely. We think the time frame that we have in mind, which is '23, '24 and kind of beyond, we think that those cost reductions are achievable. So we're bullish but we're going to do what's right for our customers.

Got you. That's super helpful color. Just can you put in context what could be the size of the opportunity from an investment perspective post that 2022, '23 time frame?

Well, I think what we said at the March 25, really, we've only given sort of guidance out to 2023, which is $1.1 billion. Now $300 million of that $1.1 billion is the offshore wind pilot that we're doing. That leaves $800 million to go toward the first phase. But I think in round numbers, we've said in excess of 2,000 megawatts. The limiting factor becomes sort of the wake effect that you have with 1 turbine sort of stacked up behind the second. But we clearly see line of sight in excess of 2,000 megawatts. And I would pencil out maybe a $3,000 per kilowatt-hour installed. And if you do that, you come up with a sizable investment but that would be out over the entire decade.

This concludes our time for Q&A. I'll now turn it back to our speakers for closing comments.

Thank you for everyone's time this morning. We know it's a busy earnings day and the Investor Relations team is available, of course, to answer questions throughout the rest of the day. Thank you.

Thank you. Ladies and gentlemen, this concludes this morning's conference call. You may disconnect your lines and enjoy your day. Thank you.